UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549



FORM 10-Q



ý

Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the quarterly period ended September 30, 2016Oro

Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period
from                to


Commission File Number: 000-06910



TEL OFFSHORE TRUST(Exact name of registrant as specified in its charter)



Texas(State or other jurisdiction of
incorporation or organization)

76-6004064(I.R.S. Employer
Identification No.)The Bank of New York Mellon Trust Company, N.A.
919 Congress Avenue
Austin, Texas(Address of principal executive offices)

78701(Zip Code)


(512) 236-6599(Registrant's telephone number, including area code)

Indicate
by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days. Yes ý    No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to
be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files). Yes o    No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the
definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.



Large accelerated filer o

Accelerated filer o

Non-accelerated filer ý (Do not check if a
smaller reporting company)

Smaller reporting company o


Indicate
by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act). Yes o    No ý

As of November 11, 2016, 4,751,510 Units of Beneficial Interest in TEL Offshore Trust were outstanding.







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NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this "Form 10-Q") includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts
included in this Form 10-Q, including without limitation, statements under "Trustee's Discussion and Analysis of Financial Condition and Results of Operations" in Item 2 of Part I
and elsewhere herein regarding the financial position, production and reserve growth, and other plans and objectives are forward-looking statements. Forward-looking statements are generally
accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "could," "may," "should," "intend" or other words that convey the uncertainty of future events or
outcomes. These forward-looking statements are based on current expectations and assumptions about future events. Although Chevron USA, Inc., the Managing General Partner of the TEL Offshore
Trust Partnership, has advised the Trust that the Managing General Partner believes that the expectations reflected in the forward-looking statements contained herein are reasonable, no assurance can
be given that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from expectations are disclosed in the risk factors discussed in
Item 1A of Part I of the Trust's Annual Report on Form 10-K for the year ended December 31, 2015 (the "2015 10-K") and such other factors as may be set forth from time to
time in the Trust's filings with the Securities and Exchange Commission. All subsequent written and oral forward-looking statements attributable to the Managing General Partner or the Trust or persons
acting on behalf of the Managing General Partner or the Trust are expressly qualified in their entirety by such factors. The Trust assumes no obligation, and disclaims any duty, to update these
forward-looking statements.

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PART IFINANCIAL INFORMATION

Item 1.    Condensed Financial Statements.

TEL OFFSHORE TRUST  CONDENSED STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS (UNAUDITED)



September 30,
2016

December 31,
2015AssetsCash and cash equivalents

$
22,230

$
328,040CashRestricted


1,761,572


Net overriding royalty interest in oil and gas properties, net of accumulated amortization of $0 and $28,258,358, respectively





9,297​
​
​
​
​
​
​
​Total assets

$
1,783,802

$
337,337​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​Liabilities and Trust CorpusDistribution payable to Unit holders

$


$
Cash advances


68,224


8,303Account payable





878Note payable


1,056,885


1,056,885Reserve for future Trust expenses





Trust corpus (4,751,510 Units of beneficial interest authorized and outstanding)


658,693


(728,729
)​
​
​
​
​
​
​
​Total liabilities and Trust corpus

$
1,783,802

$
337,337​
​
​
​
​
​
​
​​
​
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​​
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1

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CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME (UNAUDITED)



Three Months Ended
September 30,

Nine Months Ended
September 30,2016

2015

2016

2015Royalty income

$


$


$
117,142

$
Interest income


658





805Proceeds from sale of overriding royalty interest








1,756,624


​
​
​
​
​
​
​
​
​
​
​
​
​
​658





1,874,571


Income withheld for future probate distribution


(658
)




(1,873,799
)

Decrease in reserve for future Trust expenses











Proceeds from Note and cash advances used for Trust expenses


153,757


96,765


477,079


334,255General and administrative expenses


(153,757
)

(96,765
)

(477,851
)

(334,255
)​
​
​
​
​
​
​
​
​
​
​
​
​
​Distributable income











​
​
​
​
​
​
​
​
​
​
​
​
​
​Distributable income per Unit (basic and diluted (4,751,510 Units))

$
0.000000

$
0.000000

$
0.000000

$
0.000000​
​
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​​
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​
​
​
​
​
​Distributions per Unit (4,751,510 Units)

$
0.000000

$
0.000000

$
0.000000

$
0.000000​
​
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CONDENSED STATEMENTS OF CHANGES IN TRUST CORPUS (UNAUDITED)



Three Months Ended
September 30,

Nine Months Ended
September 30,2016

2015

2016

2015Trust corpus, beginning of period

$
811,792

$
(462,050
)
$
(728,729
)
$
(223,304
)Distributable income











Distribution payable to Unit holders











Sales proceeds








1,873,052


Proceeds from Note and cash advances used for Trust expenses


(153,757
)

(96,765
)

(477,079
)

(334,255
)Interest Income


658





746


Amortization of net overriding royalty interest





(537
)

(9,297
)

(1,793
)​
​
​
​
​
​
​
​
​
​
​
​
​
​Trust corpus, end of period

$
658,693

$
(559,352
)
$
658,693

$
(559,352
)​
​
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The accompanying notes are an integral part of these condensed financial statements.

2

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TEL OFFSHORE TRUST        NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED)

(1) Trust Organization

Tenneco Offshore Company, Inc. ("Tenneco Offshore") created the TEL Offshore Trust ("Trust") effective January 1, 1983, pursuant to the Plan of Dissolution ("Plan")
approved by Tenneco Offshore's stockholders on December 22, 1982. In accordance with the Plan, the TEL Offshore Trust Partnership ("Partnership") was formed in which the Trust owns a 99.99%
interest and Tenneco Oil Company had initially owned a .01% interest. In general, the Plan was effected by transferring an overriding royalty interest equivalent to a 25% net profits interest (the
"Original Royalty") in the oil and gas properties (the "Royalty Properties") of Tenneco Exploration, Ltd. located offshore Louisiana to the Partnership and issuing certificates evidencing units
of beneficial interest in the Trust ("Units") in liquidation and cancellation of Tenneco Offshore's common stock. The term "Original Royalty" shall refer to the initial 25% net profits interest in the
Royalty Properties and the term "Royalty" shall refer to the applicable net profits interest previously held from time to time by the Partnership following the Royalty Sales (as defined in
Note 3 below).

On
January 14, 1983, Tenneco Offshore distributed Units to holders of Tenneco Offshore's common stock on the basis of one Unit for each common share owned on such date.

The
terms of the Trust Agreement, dated January 1, 1983 (as amended, the "Trust Agreement"), provide, among other things, that:



3

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(1) Trust Organization (Continued)

On
October 27, 2011, the Partnership sold 20% of the Original Royalty (or 5% of 8/8ths) for gross proceeds of $1,600,000. See Note 3.

On
October 31, 2013, the Partnership consummated the sale of 25% of its remaining interest in the Original Royalty (or 5% of 8/8ths) for gross proceeds of $1,200,000. See
Note 3.

On
June 24, 2016, the Partnership consummated the sale of all of its remaining interest in the Original Royalty (or 15% of 8/8ths) owned by the Partnership. As a result of
consummation of the sale, the Partnership no longer owns any overriding royalty interest in the Royalty Properties. See Note 3.

The
Trust is currently administered by The Bank of New York Mellon Trust Company, N.A. (the "Corporate Trustee"), which succeeded JPMorgan Chase Bank, N.A. as the corporate trustee,
effective October 2, 2006 pursuant to an agreement under which The Bank of New York acquired substantially all of the corporate trust business of JPMorgan Chase (formerly known as The Chase
Manhattan Bank), and Gary C. Evans, Thomas H. Owen, Jr., and Jeffrey S. Swanson (the "Individual Trustees"), as trustees (collectively, the "Trustees").

The
Trustees, including the Corporate Trustee, have no authority over, have not evaluated and make no statement concerning, the internal control over financial reporting of any of the
owner or owners of the Royalty Properties (the "Working Interest Owners").

(2) Basis of Accounting and Going Concern

The accompanying unaudited financial information has been prepared by the Corporate Trustee. The accompanying financial information is prepared on a comprehensive basis of accounting
other than accounting principles generally accepted in the United States of America ("GAAP"). The Trustees believe that the information furnished reflects all adjustments that are, in the opinion of
the Trustees, necessary for a fair presentation of the results for the interim periods presented. Such adjustments are of a normal and recurring nature. The financial information should be read in
conjunction with the financial statements and notes thereto included in the Trust's Annual Report on Form 10-K for the year ended December 31, 2015.

Overriding Royalty Interest.The Trust uses the modified cash basis of accounting to report Trust receipts from the overriding royalty
and payments
of expenses incurred. Actual cash distributions to the Trust were made based on the terms of the conveyance that created the Trust's overriding royalty interest. Prior to the Royalty Sales (as defined
in Note 3), the overriding royalty interest entitled the Trust to receive revenues (oil, gas and natural gas liquid sales) less expenses (the amount by which all royalties, lease operating
expenses including well workover costs, production and property taxes, post-production costs including plugging and abandonment, and producing overhead of the underlying properties) multiplied by the
Partnership's interest in the Original Royalty. The Original Royalty initially represented a 25% net profits interest but after the Royalty Sales, the Partnership no longer owns any overriding
interest in the Royalty properties. Actual cash receipts would vary due to timing

4

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(2) Basis of Accounting and Going Concern (Continued)

delays
of cash receipts from the property operators or purchasers and due to wellhead and pipeline volume balancing agreements or practices.

Modified Cash Basis of Accounting.The condensed financial statements of the Trust, as prepared on a modified cash basis, reflect the
Trust's assets,
liabilities, Trust corpus, earnings and distributions, as follows:



This
manner of reporting income and expenses is considered to be the most meaningful because the quarterly distributions to Unit holders are based on net cash receipts received from the
Working Interest Owners. The condensed financial statements of the Trust differ from condensed financial statements prepared in accordance with GAAP, because, under such principles, Royalty income and
Trust general and administrative expenses for a quarter would be recognized on an accrual basis. In addition, amortization of the net overriding royalty interest, calculated on a units-of-production
basis, was charged directly to Trust corpus since such amount did not affect distributable income. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for
royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E,Financial Statements of Royalty
Trusts.

Oil and Gas Reserves.The proved oil and gas reserves for the underlying properties have been estimated by independent petroleum
engineers. Reserve
engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof. Estimates by different

5

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(2) Basis of Accounting and Going Concern (Continued)

engineers
often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors
such as changes in product prices and production costs, may justify revision of such estimates. Accordingly, oil and gas quantities ultimately recovered and the timing of production may be
substantially different from estimates.

The
standardized measure of discounted future net cash flows is prepared using assumptions made pursuant to FASB and SEC guidelines. Such assumptions include using average fiscal-year
oil and gas prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month reporting period) and year-end costs for estimated future
production expenditures. Discounted future net cash flows are calculated using a 10% discount rate. Changes in any of these assumptions could have a significant impact on the standardized measure. The
standardized measure does not necessarily result in an estimate of the current fair market value of proved reserves.

Amortization of Overriding Royalty Interest.The Trust amortized the investment in overriding royalty interest using the
units-of-production method.
The Trust's rate of recording amortization was dependent upon the estimates of total proved reserves, which incorporated various assumptions and future projections. If the estimates of total proved
reserves declined significantly, the rate at which the Trust recorded amortization expense would have increased, reducing Trust corpus. Such a decline in reserves may result from lower commodity
prices, which may make it uneconomic to produce from higher cost fields. As a result of the 2016 Royalty Sale, the Trust no longer holds any investment in the overriding royalty interest and there
will be no further amortization.

Impairment of Investment in Overriding Royalty Interest.The Trust reviewed overriding royalty interests in oil and gas properties for
possible
impairment whenever events or circumstances indicated the carrying amount of the asset may not be recoverable. If there was an indication of impairment, the Trust prepared an estimate of future cash
flows (undiscounted and without interest charges) expected to result from the use of the asset and its eventual disposition. If these cash flows were less than the carrying amount of the asset, an
impairment loss was recognized to write down the asset to its estimated fair value. Preparation of estimated expected future cash flows is inherently subjective and was based on the Corporate
Trustee's best estimate of assumptions concerning expected future
conditions. As a result of the 2016 Royalty Sale, the Trust no longer holds any investment in the overriding royalty interest and there will be no further impairments.

Cash and Cash Equivalents.Cash and cash equivalents include all highly liquid short-term investments with original maturities of three
months or
less.

Restricted Cash.Restricted cash reported on the Condensed Statement of Assets, Liabilities and Trust Corpus consists of (i)
 proceeds received
by the Trust from the 2016 Royalty Sale and (ii) the distribution received by the Trust as a result of the Cox Oil Sale (as defined in Note 6). The proceeds from the 2016 Royalty Sale
are required to be held in a segregated account pending resolution of the

6

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(2) Basis of Accounting and Going Concern (Continued)

Probate
Proceeding (as defined in Note 6). The distribution received in connection with the Cox Oil Sale (as defined in Note 6) is also being withheld by the Trust pending resolution of
the Probate Proceeding.

Reserve for future Trust expenses.Represents cash reserves for future Trust expenses established by the Trustee. The changes in
reserves for future
Trust expenses include both changes of amounts deemed necessary by the Trustees and related distributions, as well as amounts paid from the reserve during periods when the Trust has insufficient
income to pay Trust expenses. See Note 6.

Proceeds from Sale of Overriding Royalty.The Trust recorded proceeds from the sale of overriding royalty interests when received.

Special Cost Escrow account.The Special Cost Escrow account was established for future costs to be incurred to plug and abandon wells,
dismantle and
remove platforms, pipelines and other production facilities, and for the estimated amount of future capital expenditures on the Royalty Properties. The funds previously held in the Special Cost Escrow
account were not reflected in the condensed financial statements of the Trust. However, funds deposited to or released from the Special Cost Escrow account were included in Royalty income. See
Note 5.

Use of Estimates.The preparation of financial statements requires the Trustees to make use of estimates and assumptions that affect
amounts reported
in the condensed financial statements as well as certain disclosures. Actual results could differ from those estimates.

Recent Accounting Pronouncements.There were no accounting pronouncements issued during the three months ended September 30, 2016,
applicable
to the Trust or its condensed financial statements.

Going Concern.The accompanying condensed financial statements have been prepared assuming that the Trust will continue as a going
concern. Financial
statements prepared on the going concern basis assume the realization of assets and the settlement of liabilities in the normal course of business. During the first quarter of 2016, the Trust received
$713 in Royalty income from Fieldwood Energy Offshore LLC ("Fieldwood"), the operator of Eugene Island 342. In addition, as a result of the sale by Chevron of its interest in Ship Shoal 182/183
effective August 1, 2015 to Cox Oil Offshore, L.L.C. ("Cox Oil"), the Trust received a distribution of $116,429 in May 2016. As a result of the Partnership's sale of the remaining Royalty in
the 2016 Royalty Sale (as defined in Note 3 below), the Trust will not be receiving any further Royalty income and the proceeds from such sale are required to be held in a segregated interest
bearing account, which is presented as Cash-Restricted in the Condensed Statements of Assets, Liabilities and Trust Corpus, pending a subsequent court order from the Court (as defined in
Note 6). The Trust will not make any distribution of the proceeds from the 2016 Royalty Sale to Unit holders until it receives a subsequent order from the Court or the Remaining Matters (as
defined in Note 6) are otherwise settled. In addition, the Trust may refrain from making any distribution of such proceeds until after the expiration of the audit period provided for in the
conveyance document for the 2016 Royalty Sale, which expires on December 29, 2016. The lack of Net Proceeds and the inability to maintain adequate cash reserves raise substantial doubt about
the Trust's

7

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(2) Basis of Accounting and Going Concern (Continued)

ability
to continue as a going concern. The condensed financial statements do not include any adjustments that might result from the outcome of the Probate Proceeding.

(3) Net Overriding Royalty Interest

The Original Royalty entitled the Trust to its share (99.99%) of 25% of the Net Proceeds attributable to the Royalty Properties. The Conveyance, dated January 1, 1983, provided
that the Working Interest Owners would calculate, for each period of three months commencing the first day of February, May, August and November, an amount equal to 25% of the Net Proceeds from their
oil and gas properties for the period. Generally, "Net Proceeds" means the amount received by the Working Interest Owners from the sale of minerals from the Royalty Properties less operating and
capital costs incurred, management fees and expense reimbursements owing to the Managing General Partner of the Partnership, applicable taxes other than income taxes, and the Special Cost Escrow
account. The Special Cost Escrow account was established for the future costs to be incurred to plug and abandon wells, dismantle and remove platforms, pipelines and other production facilities, and
for the estimated amount of future capital expenditures on the Royalty Properties. Net Proceeds did not include amounts received by the Working Interest Owners as advance gas payments, "take-or-pay"
payments or similar payments unless and until such payments were extinguished or repaid through the future delivery of gas.

On
October 27, 2011, the Trust issued a press release announcing that the Partnership had consummated the sale (the "2011 Royalty Sale") of 20% of the Original Royalty (or 5% of
8/8ths). The 2011 Royalty Sale was made to RNR Production, Land and Cattle Company, Inc. ("RNR Production")
on October 27, 2011, though the assignment was effective as of August 1, 2011. Refer to Note 6 for further discussion of the 2011 Royalty Sale.

On
October 31, 2013, the Trust issued a press release announcing that the Partnership had consummated the sale (the "2013 Royalty Sale") of 25% of its remaining interest in the
Original Royalty (or 5% of 8/8ths). The 2013 Royalty Sale to RNR Production closed on October 31, 2013, though the assignment was effective as of August 1, 2013. Refer to Note 6
for further discussion of the 2013 Royalty Sale.

On
June 27, 2016, the Trust issued a press release announcing that the Partnership had consummated the sale (the "2016 Royalty Sale" and, together with the 2011 Royalty Sale and
the 2013 Royalty Sale, the "Royalty Sales") of all of its remaining interest in the Original Royalty (60% or 15% of 8/8ths). As a result of consummation of the 2016 Royalty Sale, the Partnership no
longer owns any Royalty in the Royalty Properties. The 2016 Royalty Sale was made to Arena Energy, LP and closed on June 24, 2016, but was effective as of February 1, 2016. The
2016 Royalty Sale generated $1,830,000 in gross proceeds and occurred as part of the previously announced formal auction process for the overriding royalty interest. The Trust received a distribution
of approximately $1,756.624, representing 99.99% of the net proceeds from the Royalty Sale of $1,756,800 in July 2016. See Note 6 for a further discussion of the 2016 Royalty Sale.

8

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(3) Net Overriding Royalty Interest (Continued)

On the last business day of each calendar quarter prior to August 1, 2011, the Working Interest Owners were to pay to the Partnership 25% of the Net Proceeds for the immediately
preceding Quarterly Period; however, (i) as a result of the 2011 Royalty Sale, on the last business day of each calendar quarter after August 1, 2011 and prior to August 1, 2013,
the Working Interest Owners were to pay to the Partnership 20% of the Net Proceeds for the immediately preceding Quarterly Period (ii) as a result of the 2013 Royalty Sale, on the last business
day of each calendar quarter after August 1, 2013, the Working Interest Owners were to pay to the Partnership 15% of the Net Proceeds for the immediately preceding Quarterly Period and
(iii) as a result of the 2016 Royalty Sale, from and after February 1, 2016, the Working Interest Owners are no longer required to pay to the Partnership any Net Proceeds. A Quarterly
Period is each period of three months commencing on the first day of February, May, August and November. In turn, the Partnership distributed funds to its partners on the last business day of each
calendar quarter. Cash distributions from the Trust, if any, were made in January, April, July and October of each year, and were payable to Unit holders of record as of the last business day of each
calendar quarter. The financial and operating information included in this Form 10-Q for the three and nine months ended September 30, 2016 and September 30, 2015 represents
financial and operating information with respect to the Royalty Properties for the immediately preceding months of November, December, January, February, March, April, May, June and July. Income
received pursuant to the Partnership's overriding royalty interest was recorded by the Trust on a cash basis, when it was received by the Trust from the Partnership.

(4) Distributions to Unit Holders

In accordance with the provisions of the Trust Agreement, generally all Net Proceeds received by the Trust, net of Trust general and administrative expenses and any cash reserves
established for the payment of contingent or future obligations of the Trust, are distributed quarterly to the Unit holders. These distributions are referred to as "distributable income." The amounts
distributed, if any, are determined on a quarterly basis and are payable to Unit holders of record as of the last business day of each calendar quarter. Cash distributions, when available, are made in
January, April, July and October and include interest earned from the quarterly record date to the date of distribution.

Production
ceased at Eugene Island 339 and Ship Shoal 182 and 183 following damages inflicted by Hurricane Ike in September 2008. Future Net Proceeds took into account the Trust's share
of project costs and other related expenditures that were not covered by insurance of the operator of the Royalty Properties. On December 19, 2008, the Trust announced its fourth quarter
distribution of approximately $0.7 million, which was paid on January 9, 2009. The funds available for the fourth quarter distribution were severely negatively impacted by lower
production as a result of shutdowns and damage to producing assets because of Hurricane Ike. On March 25, 2009, the Trust announced that there would be no trust distribution for the first
quarter of 2009, and the Trust has not made a distribution since January 9, 2009.

The
Trust currently holds the net proceeds from the 2016 Royalty Sale and remaining proceeds received as a result of the Cox Oil Sale (as defined in Note 6), a portion of such
proceeds having been

9

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(4) Distributions to Unit Holders (Continued)

used
to pay certain expenses of the ad litem in the Probate Proceeding. The Trust will not make any distribution of these funds to Unit holders until it receives a subsequent order from the Court or
the Remaining Matters are otherwise settled. In addition, the Trust may refrain from making any distribution of such proceeds until after the expiration of the audit period provided for in the
conveyance document for the 2016 Royalty Sale, which expires on December 24, 2016.

(5) Special Cost Escrow Account

The Special Cost Escrow is an account of the Working Interest Owners, and it is described herein for informational purposes only. The Conveyance provides for reserving funds for
estimated future "Special Costs" of plugging and abandoning wells, dismantling platforms and other costs of abandoning the Royalty Properties, as well as for the estimated amount of future drilling
projects and other capital expenditures on the Royalty Properties. Deposits into this account reduce current distributions and are placed in an escrow account and invested in short-term certificates
of deposit. Such account is herein referred to as the "Special Cost Escrow" account. As of September 30, 2016, $1,000 remained in the Special Cost Escrow account. The funds held in the Special
Cost Escrow account are not reflected in the condensed financial statements of the Trust. All of the Partnership's rights and obligations with respect to the Special Cost Escrow were assigned in
connection with the Royalty Sales.

(6) Reserve For Future Trust Expenses; Probate Proceeding

Historically, the Trust generally maintained a cash reserve, equal to approximately three times the average annual expenses of the Trust during each of the then past three years, to
provide for future administrative expenses in connection with the winding up of the Trust. However, as a result of the damage inflicted upon certain of the Royalty Properties by Hurricane Ike in
September 2008, the Trust has not received sufficient Net Proceeds to maintain the reserve at such level. As of September 30, 2016 and December 31, 2015 the reserve amount was $0.

During
the first quarter of 2016, the Trust received Royalty income of $713 attributable to Eugene Island 342. On April 15, 2016, but effective as of August 1, 2015,
Chevron conveyed certain oil and gas properties to Cox Oil, including Chevron's interest in Ship Shoal 182/183 that was subject to the Royalty (the "Cox Oil Sale"). Any Net Proceeds from Cox Oil
attributable to Ship Shoal 182/183 are not subject to offset by Chevron against the undistributed net loss carry forward attributable to the Royalty Properties held by Chevron. As a result of the
August 1, 2015 effective time and the Ship Shoal 182/183 properties not being subject to the undistributed net loss carry forward, the Trust received a distribution from Cox Oil of $116,429 in
May 2016. The Trust also received net proceeds of $1,756,624 from the 2016 Royalty Sale; however, the net proceeds from the 2016 Royalty Sale are not available to the Trust for the payment of costs
and expenses pending the resolution of the Probate Proceeding. In addition, the remaining proceeds received as a result of the Cox Oil Sale are also being separately withheld and are not available to
the Trust for the payment of costs and expenses unless approved by the ad litem pending the resolution of the Probable Proceeding. As a result of the 2016 Royalty Sale, the Trust will not receive any
further Net Proceeds from the Royalty Properties. As of

10

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(6) Reserve For Future Trust Expenses; Probate Proceeding (Continued)

September 30,
2016, including the proceeds from the 2015 Note (as defined below) and additional cash advances, the Trust's available cash was approximately $22,230. Based upon currently
estimated expenditures, inclusive of the costs and expenses relating to the Probate Proceeding, it is anticipated that the Trust's available cash will be depleted during the fourth quarter of 2016.
Following the depletion of the Trust's available cash, the Trustees will endeavor to cause the Trust to pay the administrative costs of the Trust in accordance with the Trust Agreement. There are no
assurances that the Trust will be able to continue to pay its administrative expenses.

Pursuant
to the terms of the Trust Agreement, the Trustees are authorized to borrow funds, and pledge the assets of the Trust to secure payments of such borrowings, in the event that
cash on hand is not sufficient to pay the liabilities of the Trust. In the event that the Trustees borrow funds to pay the liabilities of the Trust, no distributions may be made to the Unit holders
until the indebtedness created by such borrowings has been paid in full. As discussed in Note 9, the Trustees borrowed, and may in the future borrow, funds from which a portion of the proceeds
were, or may be, used to pay for Trust expenses.

The
Trust Agreement further provides that, if necessary to provide for the payment of specific liabilities of the Trust then due, the Trustees may without a vote of the Unit holders
(a) sell all or a portion of the Trust's interest in the Partnership or any other assets of the Trust for such cash consideration as the Trustees shall deem appropriate, (b) exercise
their rights under the Partnership Agreement to dissolve the Partnership, or (c) cause a sale by the Partnership of the overriding royalty interest owned by the Partnership.

In
connection with the 2011 Royalty Sale, the Trust received from the Partnership a distribution of approximately $1,485,851 and used such net proceeds solely for the payment of expenses
of the Trust. In connection with the 2013 Royalty Sale, the Trust received from the Partnership a distribution of approximately $1,151,885 and used approximately $300,000 of the net proceeds received
in October 2013 to repay the Trust's indebtedness under a previous note payable to BONYM and used the remaining net proceeds solely for the payment of expenses of the Trust. See Note 3 for more
information about the Royalty Sales.

In
March 2014, the Trustees unanimously determined to suspend future payments of fees to the Trustees effective as of January 1, 2014, until a date to be determined in the future
by the Trustees. As of September 30, 2016, the amount of such fees was approximately $471,470 in the aggregate. Such suspended fees will be recorded as an expense of the Trust when invoiced by
the Trustees and paid.

On
July 10, 2014, the Trustees filed a Petition for Modification and Termination of the Trust (the "Petition") with the Probate Court of Travis County, Texas (the "Court"). The
Petition requested that the Court modify the Trust Agreement to (1) allow for the termination of the Trust by a court order, and (2) allow the Trustees, as necessary to fulfill the
purposes of the Trust and without Unit holder approval to (a) sell all or any portion of the Trust's interests in the Partnership or any other assets of the Trust, (b) exercise their
rights to dissolve the Partnership, or (c) cause the Partnership to sell the Royalty. The goals in filing such probate proceeding (the "Probate Proceeding") were to permit the

11

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(6) Reserve For Future Trust Expenses; Probate Proceeding (Continued)

Trustees
to direct the Partnership to sell the Royalty; to distribute the net proceeds resulting from such sale, after payment of the Trust's liabilities, to the Unit holders; and, to, thereafter
terminate the Partnership and the Trust. The Trust has completed the process of serving the Petition on the Trust's Unit holders. The Court appointed an attorney ad litem to represent any Unit holders
that were not personally served. The Court appointed attorney ad litem filed a Counterclaim against the Trust on November 16, 2015 requesting (1) an order to sell all of the Royalty, and
(2) an accounting of the general and administrative expenses of the Trust from 2008 through the present.

The
Probate Proceeding was set for trial on January 15, 2016. Prior to trial, the attorney ad litem filed a Motion to Sever asking the Court to sever all matters related to the
requested modification of the Trust and the sale of Trust assets, as plead for, in part, in the petition originally filed by the Trustees and in the attorney ad litem's Counterclaim, into a separate
cause to proceed to trial. The attorney ad litem also filed a Motion for Continuance requesting that the Court continue the trial of all remaining matters, including the attorney ad litem's request
for an accounting and the issues concerning the termination of the Trust, to a later date (the "Remaining Matters"). Prior to calling the case to trial, the Court granted the attorney ad litem's
Motion to Sever and Motion for Continuance, severed the matters related to the modification of the Trust and the sale of Trust assets ("Severed Proceeding"), and continued the Remaining Matters to a
later date. The Severed Proceeding has been assigned Cause No. C-1-PB-16-000096 and is styledIn re: TEL Offshore Trust.

The
Severed Proceeding proceeded to trial before the Court on January 15, 2016. At trial, the Court entered a Final Judgment and Order (the "Order") granting the Trustees' request
that the Trust Agreement be modified to permit the Trustees to direct the Partnership to sell the remaining overriding royalty interest held by the Partnership as soon as reasonably possible and
granting the ad litem's request to sell all of the Royalty, notwithstanding any requirements of the Trust Agreement to the contrary. Thereafter, the Court ordered that the Trustees direct the
Partnership to sell all of the Royalty owned by the Partnership on or before May 1, 2016. On April 25, 2016, the Court approved an extension of the May 1, 2016 deadline to
June 30, 2016.

On
August 17, 2016, the attorney ad litem filed a Second Amended Answer and First Amended Counterclaim seeking an accounting and asserting, among other causes of action, that the
Trustees have breached their fiduciary duties to the beneficiaries of the Trust. The Remaining Matters were originally set for trial on November 7, 2016. Trustees filed a motion for continuance
of the Remaining Matters and a hearing for such continuance occurred on September 14, 2016. At the hearing, the Court granted the Trustees' motion for continuance of the Remaining Matters and
scheduled the trial for June 12, 2017. There can be no assurances as to the outcome of the Remaining Matters and whether the Court will grant the requested relief, and if such relief is
granted, when such actions will be completed.

On
June 27, 2016, the Trust issued a press release announcing that the Partnership had consummated the 2016 Royalty Sale on June 24, 2016. The sale was made in accordance
with the Order pursuant to which the Court ordered that the Trustees of the Trust direct the Partnership to sell all of the royalty interests owned by the Partnership. In connection with the 2016
Royalty Sale the Trust

12

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(6) Reserve For Future Trust Expenses; Probate Proceeding (Continued)

received
a distribution of approximately $1,756.624. Due to the Remaining Matters, the Trust must hold the net proceeds in a segregated account until the Court's final resolution of the Remaining
Matters. Distributions may be made from such segregated account for the payment of Trust expenses, which may include the payment of the ad litem's expenses, with the approval of the Court. Any final
disposition of the remaining net proceeds will be made in accordance with the final resolution of the Remaining Matters. In addition, the Trust may refrain from making any distribution of the net
proceeds received from the 2016 Royalty Sale until the expiration of the audit period provided for in the conveyance document for the 2016 Royalty Sale, which expires on December 24, 2016.

(7) Federal Income Tax Matters

The IRS has ruled that the Trust is a grantor trust and that the Partnership is a partnership for federal income tax purposes. Thus, the Trust will incur no federal income tax liability
and each Unit holder will be treated as owning an interest in the Partnership.

(8) Related Party Transactions

Each of the Working Interest Owners owned interests, for its own account, in leases that were in the same area as leases in which the Partnership had previously held an interest. Such
relationships may have given rise to potential conflicts of interests in, among other things, the operation of such leases and in the acquisition and operation of any drainage leases acquired by a
Working Interest Owner for its own account. Additionally, the Working Interest Owners and their affiliates were not prohibited
from purchasing oil and gas produced from or attributable to any leases in which the Partnership had an interest.

Crude
oil sales to Chevron Corporation accounted for 0% and 100% of crude oil revenues from the Royalty Properties for the three and nine months ended September 30, 2016 and 2015,
respectively. Sales to Chevron Corporation accounted for 0% and 100% of total gas revenues from the Royalty Properties during the three and nine months ended September 30, 2016 and 2015,
respectively.

The
Trust's share of Royalty income was reduced by approximately $0 and $13,891 for each of the three months ended September 30, 2016 and September 30, 2015, respectively,
and $11,644 and $43,457 for each of the nine months ended September 30, 2016 and September 30, 2015, respectively, for management fees paid to the Working Interest Owners as
reimbursement for expenses incurred by them on behalf of the Trust. The aggregate amount of management fees paid to the Working Interest Owners was calculated as 3% of the Trust's share of the sum of
revenues, production expenses and capital expenditures attributable to the Royalty Properties in each of the periods above.

(9) Note Payable

On October 1, 2014, The Bank of New York Mellon made an advance to the Trust in the amount of $363,000, and The Bank of New York Mellon Trust Company, N.A., in its capacity as
corporate trustee, as the borrower, entered into a Demand Promissory Note (the "2014 Note") with BONYM,

13

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TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(9) Note Payable (Continued)

relating
to the unsecured $363,000 advance, which evidenced an extension of credit for borrowed money authorized under Section 6.08 of the Trust Agreement. The 2014 Note provided for interest
at the rate of one-half percent (0.5%) per annum. Pursuant to the terms of the 2014 Note, all amounts outstanding under the 2014 Note were scheduled to be due and payable in cash on the earliest to
occur of (i) the date written demand for payment is made by BONYM or (ii) December 31, 2015. The Trust could prepay any outstanding principal and accrued and unpaid interest under
the 2014 Note, in whole or in part, at any time without penalty. In addition to the 2014 Note, through September 25, 2015, BONYM made additional cash advances in the amount of $209,885 to the
Trust for the payment of its liabilities and expenses, primarily in connection with the Probate Proceeding.

On
September 25, 2015, BONYM made an additional advance to the Trust in the amount of $484,000, and the Corporate Trustee, as the borrower, has entered into a Renewal Demand
Promissory Note (the "2015 Note") with BONYM, in the original principal amount of $1,056,885 relating to (i) the unsecured $484,000 advance, (ii) the renewal and extension of the
indebtedness originally evidenced by the 2014 Note in the original principal amount of $363,000, and (iii) previous advances in the amount of $209,885 made by BONYM on behalf of the Trust. The
2015 Note bears interest at the rate of one-half percent (0.5%) per annum. Pursuant to the terms of the 2015 Note, all amounts outstanding under the 2015 Note, including accrued and unpaid interest,
will be due and payable in cash on the earliest to occur of (i) the date written demand for payment is made by BONYM or (ii) December 31, 2016. In addition, the accrued and unpaid
interest remaining due from the 2014 Note in the amount of $1,790 is due and payable concurrently with the payment of the 2015 Note. The Trust may prepay any outstanding principal and accrued and
unpaid interest under the 2015 Note, in whole or in part, at any time without penalty.

In
addition to the 2015 Note, through September 30, 2016, BONYM has made additional advances in the amount of $68,224 to the Trust for the payment of its liabilities and expenses,
primarily in connection with the Probate Proceeding.

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Item 2.    Trustee's Discussion and Analysis of Financial Condition and Results of Operations.

Overview

The TEL Offshore Trust, which we refer to herein as the "Trust," was created under the laws of the State of Texas in 1983 and maintains its
offices at the office of The Bank of New York Mellon Trust Company, N.A., whom we refer to as the "Corporate Trustee," 919 Congress Avenue, Suite 500, Austin, Texas 78701. The telephone number
of the Corporate Trustee is (512) 236-6599. Gary C. Evans, Thomas H. Owen, Jr. and Jeffrey S. Swanson serve as individual trustees of the Trust and are referred to herein as the "Individual
Trustees." The Individual Trustees and the Corporate Trustee may be referred to hereinafter collectively as the "Trustees."

The
Corporate Trustee does not maintain a website for filings by the Trust with the U.S. Securities and Exchange Commission, which we refer to herein as the "SEC." Electronic filings by
the Trust with the
SEC are available free of charge through the SEC's website at www.sec.gov. The Trust will also provide paper copies of its recent filing free upon request to the Corporate Trustee.

The
principal asset of the Trust consists of a 99.99% interest in the TEL Offshore Trust Partnership, which we refer to herein as the "Partnership." Chevron U.S.A., Inc., or
"Chevron," owns the remaining .01% interest in the Partnership and is the Managing General Partner of the Partnership. Until October 27, 2011, the Partnership owned 100% of an overriding
royalty interest equivalent to a 25% net profits interest (the "Original Royalty"), in certain oil and gas properties, which we refer to herein as the "Royalty Properties," located offshore Louisiana.
The term "Original Royalty" shall refer to the initial 25% net profits interest in the Royalty Properties and the term "Royalty" shall refer to the applicable net profits interest held from time to
time by the Partnership following the Royalty Sales (as defined below).

On
June 27, 2016, the Trust issued a press release announcing that the Partnership had consummated the sale of all of its remaining interest in the Original Royalty (60% or 15% of
8/8ths) (the "2016 Royalty Sale"). The 2016 Royalty Sale was made to Arena Energy, LP and closed on June 24, 2016, but was effective as of February 1, 2016. Due to the effective
time of the 2016 Royalty Sale, the Trust no longer had any interest in, or any operating and financial results attributable to, the Royalty or the Royalty Properties as of February 1, 2016. As
a result, the Trust has not provided any additional explanation for the corresponding decreases in revenues and production under "Three Months Ended September 30, 2016 and 2015"
below.

Liquidity and Capital Resources

Prior to the sale of the remaining Royalty held by the Partnership in June 2016, the Trust's primary source of liquidity and capital had been
the Royalty income received from its share of the Net Proceeds from the Royalty Properties. Generally, "Net Proceeds" means the amounts received by the owner or owners of the Royalty Properties (the
"Working Interest Owners") from the sale of minerals from the Royalty Properties less operating and capital costs incurred, management fees and expense reimbursements owing to the Managing General
Partner of the Partnership, applicable taxes other than income taxes, and the Special Cost Escrow account. The Special Cost Escrow account, as more fully detailed in Note 5 to the condensed
financial statements, was established for the future costs to be incurred to plug and abandon wells, dismantle and remove platforms, pipelines and other production facilities, and for the estimated
amount of future capital expenditures on the Royalty Properties. Net Proceeds did not include amounts received by the Working Interest Owners as advance gas payments,

15

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"take-
or-pay" payments or similar payments unless and until such payments were extinguished or repaid through the future delivery of gas.

During
the first quarter of 2016, the Trust received Royalty income of $713 attributable to Eugene Island 342 and in the fourth quarter of 2015, the Trust received $1,316 of Royalty
income attributable to Eugene Island 342. The Trust had not received any distributions of Net Proceeds from Chevron, as operator of the Royalty Properties, since December 2008. On April 15,
2016, but effective as of August 1, 2015, Chevron conveyed certain oil and gas properties to Cox Oil Offshore, L.L.C. ("Cox Oil"), including Chevron's interest in Ship Shoal 182/183 that was
subject to the Royalty (the "Cox Oil Sale"). Any Net Proceeds from Cox Oil attributable to Ship Shoal 182/183 are not subject to offset by Chevron against the undistributed net loss carry forward
attributable to the Royalty Properties held by Chevron. As a result of the August 1, 2015 effective time and the Ship Shoal 182/183 properties not being subject to the undistributed net loss
carry forward, the Trust was entitled to receive a distribution from Cox Oil of $116,429. The Trust received the distribution in May 2016 and as a result, the undistributed net loss carry forward
attributable to the Royalty Properties increased by $116,429 from $524,335, as of January 31, 2016, to $640,764. Despite the receipt of such funds, as long as the Trust has outstanding
indebtedness, no distributions may be made by the Trust to the Unit holders. As a result of the 2016 Royalty Sale, the Trust will not receive any further Net Proceeds from the Royalty Properties.

Because
of the lack of Net Proceeds, the Trust has in the past not had sufficient cash flow to pay expenses on a current basis and as described below, the Trust has been required to
borrow funds and to cause the Partnership to sell part of the Original Royalty in order to pay Trust expenses. As of September 30, 2016, including the proceeds from the 2015 Note (as herein
defined), the previous cash advances from The Bank of New York Mellon ("BONYM") included in the principal amount of the 2015 Note and subsequent cash advances by BONYM, the Trust's unrestricted cash
was approximately $22,230. Based upon currently estimated expenditures, inclusive of the costs and expenses relating to the Probate Proceeding (as defined below), it is anticipated that the Trust's
available cash will be depleted in the fourth quarter of 2016. Following the depletion of the Trust's available cash, the Trustees will endeavor to cause the Trust to pay the administrative costs of
the Trust in accordance with the Trust Agreement. There are no assurances that the Trust will be able to continue to pay its administrative expenses.

The
Trust Agreement provides that, if necessary to provide for the payment of specific liabilities of the Trust then due, the Trustees may without a vote of the Unit holders
(a) sell all or a portion of the Trust's interest in the Partnership or any other assets of the Trust for such cash consideration as the Trustees shall deem appropriate, (b) exercise
their rights under the Partnership Agreement to dissolve
the Partnership, or (c) cause a sale by the Partnership of the overriding royalty interest owned by the Partnership. Additionally, the Trustees, on behalf of the Trust, were authorized to
borrow funds, and pledge the assets of the Trust to secure payments of such borrowings, in the event that cash on hand was not sufficient to pay the liabilities of the Trust. In the event that the
Trustees borrows funds to pay the liabilities of the Trust, no distributions will be made to the Unit holders until the indebtedness created by such borrowings has been paid in full.

On
October 27, 2011, the Trust issued a press release announcing that the Partnership had consummated the sale (the "2011 Royalty Sale") of 20% of the Original Royalty (or 5% of
8/8ths), which generated $1,600,000 in gross proceeds and occurred as part of a formal auction process for the Partnership's overriding royalty interest in the Royalty Properties. The Trust received
from the

16

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Partnership
a distribution of approximately $1,485,851, representing 99.99% of the net proceeds from the sale of $1,486,000. The 2011 Royalty Sale was made to RNR Production, Land and Cattle
Company, Inc. ("RNR Production") on October 27, 2011, though the assignment was effective as of August 1, 2011.

On
October 31, 2013, the Trust issued a press release announcing that the Partnership had consummated the sale (the "2013 Royalty Sale") of 25% of its remaining interest in the
Original Royalty (or 5% of 8/8ths), which generated $1,200,000 in gross proceeds and occurred as part of a formal auction process for the Partnership's remaining overriding royalty interest in the
Royalty Properties. The Trust received from the Partnership a distribution of approximately $1,151,885, representing 99.99% of the net proceeds from the sale of $1,152,000. The 2013 Royalty Sale was
made to RNR Production on October 31, 2013, though the assignment was effective as of August 1, 2013. The Trust used approximately $300,000 of the net proceeds received in October 2013
to repay the Trust's indebtedness under a previous note payable to BONYM and used the remaining net proceeds solely for the payment of expenses of the Trust.

In
March 2014, the Trustees unanimously determined to suspend future payments of fees to the Trustees effective as of January 1, 2014, until a date to be determined in the future
by the Trustees. As of September 30, 2016, the accumulated amount of such suspended fees was approximately $414,918 in the aggregate. The cumulative suspended fees will be recorded as an
expense of the Trust when invoiced by the Trustees and paid.

On
October 1, 2014, BONYM made a loan to the Trust in the amount of $363,000, and the Corporate Trustee, as the borrower, entered into a Demand Promissory Note (the "2014 Note")
with BONYM, as lender, relating to the unsecured $363,000 advance, which evidenced an extension of credit for borrowed money authorized under Section 6.08 of the Trust Agreement. On
September 25, 2015, BONYM made an additional advance to the Trust in the amount of $484,000 and the Corporate Trustee, as the borrower, entered into a Renewal Demand Promissory Note (the "2015
Note") with BONYM, as lender, relating to (i) the unsecured $484,000 advance, (ii) the renewal and extension of the 2014 Note, and (iii) previous advances in the amount of
$209,885 made by BONYM on behalf of the Trust. The 2015 Note bears interest at the rate of one-half percent (0.5%) per annum. Pursuant to the terms of the 2015 Note, all amounts outstanding under the
2015 Note including accrued and unpaid interest will be due and payable in cash on the earliest to occur of (x) the date written demand for payment is made by BONYM or
(y) December 31, 2016. The Trust may prepay any outstanding principal and accrued and unpaid interest under the 2015 Note, in whole or in part, at any time without penalty. In addition,
the accrued and unpaid interest remaining due from the 2014 Note in the amount of $1,790 is due and payable concurrently with the payment of the 2015 Note. During the three months ended
September 30, 2016, a portion of the proceeds from the 2014 Note, as renewed and extended by the 2015 Note, were used to pay Trust expenses.

As
indicated above, the Trustees have previously authorized the Trust to borrow funds and the Partnership to sell portions of the Original Royalty in an effort to pay the ongoing costs
and expenses incurred by the Trust in fulfilling its obligations under the Trust Agreement. As a result of the ongoing costs and expenses of the Trust and the lack of any distributions or assurances
of future distributions, on July 10, 2014, the Trustees filed a Petition for Modification and Termination of the Trust (the "Petition") with the Probate Court of Travis County, Texas (the
"Court"). The Petition requested that the Court modify the Trust Agreement to (1) allow for the termination of the Trust by a court order, and (2) allow the Trustees, as necessary to
fulfill the purposes of the Trust and without Unit holder

17

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approval
to (a) sell all or any portion of the Trust's interests in the Partnership or any other assets of the Trust, (b) exercise their rights to dissolve the Partnership, or
(c) cause the Partnership to sell the Royalty. The goals in filing such probate proceeding (the "Probate Proceeding") were to permit the Trustees to direct the Partnership to sell the Royalty;
to distribute the net proceeds resulting from such sale, after payment of the Trust's liabilities, to the Unit holders; and, to, thereafter terminate the Partnership and the Trust. The Trust has
completed the process of serving the Petition on the Trust's Unit holders. The Court appointed an attorney ad litem to represent any Unit holders that were not personally served. The Court appointed
attorney ad litem filed a Counterclaim against the Trust on November 16, 2015 requesting (1) an order to sell all of the Royalty, and (2) an accounting of the general and
administrative expenses of the Trust from 2008 through the present.

The
Probate Proceeding was set for trial on January 15, 2016. Prior to trial, the attorney ad litem filed a Motion to Sever asking the Court to sever all matters related to the
requested modification of the Trust and the sale of Trust assets, as plead for, in part, in the petition originally filed by the Trustees and in the attorney ad litem's Counterclaim, into a separate
cause to proceed to trial. The attorney ad litem also filed a Motion for Continuance requesting that the Court continue the trial of all remaining matters, including the attorney ad litem's request
for an accounting and the issues concerning the termination of the Trust, to a later date (the "Remaining Matters"). Prior to calling the case to trial, the Court granted the attorney ad litem's
Motion to Sever and Motion for Continuance, severed the matters related to the modification of the Trust and the sale of Trust assets ("Severed Proceeding"), and continued the Remaining Matters to a
later date. The Severed Proceeding has been assigned Cause No. C-1-PB-16-000096 and is styledIn re: TEL Offshore Trust.

The
Severed Proceeding proceeded to trial before the Court on January 15, 2016. At trial, the Court entered a Final Judgment and Order (the "Order") granting the Trustees' request
that the Trust Agreement be modified to permit the Trustees to direct the Partnership to sell the remaining overriding royalty interest held by the Partnership as soon as reasonably possible and
granting the ad litem's request to sell all of the Royalty, notwithstanding any requirements of the Trust Agreement to the contrary. Thereafter, the Court ordered that the Trustees direct the
Partnership to sell all of the Royalty owned by the Partnership through a sale to be conducted by EnergyNet.com, Inc. on or before May 1, 2016. On April 25, 2016, the Court
approved an extension of the May 1, 2016 deadline to June 30, 2016.

On
August 17, 2016, the attorney ad litem filed a Second Amended Answer and First Amended Counterclaim seeking an accounting and asserting, among other causes of action, that the
Trustees have breached their fiduciary duties to the beneficiaries of the Trust. The Remaining Matters were originally set for trial on November 7, 2016. Trustees filed a motion for continuance
of the Remaining Matters and a hearing for such continuance occurred on September 14, 2016. At the hearing, the Court granted the Trustees' motion for continuance of the Remaining Matters and
scheduled the trial for June 12, 2017. There can be no assurances as to the outcome of the Remaining Matters and whether the Court will grant the requested relief, and if such relief is
granted, when such actions will be completed.

On
June 27, 2016, the Trust issued a press release announcing that the Partnership had consummated the 2016 Royalty Sale (the 2016 Royalty Sale, together with the 2011 Royalty
Sale and the 2013 Royalty Sale, the "Royalty Sales"). The sale was made in accordance with the Order pursuant to which the Court ordered that the Trustees of the Trust direct the Partnership to sell
all of the royalty interests owned by the Partnership.

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The
2016 Royalty Sale was made to Arena Energy, LP and closed on June 24, 2016, but was effective as of February 1, 2016. The 2016 Royalty Sale generated $1,830,000
in gross proceeds and occurred as part of the previously announced formal auction process for the overriding royalty interest. The Trust received a distribution of approximately $1,756.624,
representing 99.99% of the net proceeds from the Royalty Sale of $1,756,800. Due to the Remaining Matters, the Trust must hold the net proceeds in a segregated account until the Court's final
resolution of the Remaining Matters. The disposition of such net proceeds will be made in accordance with the final resolution of the Remaining Matters. In addition, the Trust may refrain from making
any distribution of the net proceeds received from the 2016 Royalty Sale until the expiration of the audit period provided for in the conveyance document for the 2016 Royalty Sale, which expires on
December 24, 2016.

As
a result of the 2016 Royalty Sale, the Trust no longer owns any interest in the Royalty and therefore will not receive any further distributions of Net Proceeds. Because of the
Remaining Matters in the Probate Proceeding, the Trust must hold the net proceeds from the 2016 Royalty Sale in a segregated account until the final resolution of the Remaining Matters. In addition,
the Trust has set aside the distribution received from Cox Oil until the final resolution of the Remaining Matters. Distributions may be made from such segregated account for the payment of Trust
expenses, which may include the payment of the ad litem's expenses, with the approval of the Court. Any final disposition of the remaining net proceeds to Unit holders will be made in accordance with
the final resolution of the Remaining Matters. As discussed above, as of September 30, 2016, including the proceeds from the 2015 Note and subsequent cash advances by BONYM, the Trust's
unrestricted cash was $22,230. Based upon currently estimated expenditures, inclusive of the costs and expenses of the Probate Proceeding, it is anticipated that the Trust's available cash will be
depleted during the fourth quarter of 2016. Following the depletion of the Trust's available cash, the Trustees will endeavor to cause the Trust to pay the administrative costs of the Trust in
accordance with the Trust Agreement. There are no assurances that the Trust will be able to continue to pay its administrative expenses.

The
accompanying condensed financial statements have been prepared assuming that the Trust will continue as a going concern. Financial statements prepared on the going concern basis
assume the realization of assets and the settlement of liabilities in the normal course of business. Because of the 2016 Royalty Sale, the Trust will not receive any further Net Proceeds from the
Royalty Properties. The Trust currently holds the net proceeds from the 2016 Royalty Sale and remaining proceeds received as a result of the Cox Oil Sale, a portion of such proceeds having been used
to pay certain expenses of the ad litem in the Probate Proceeding. The Trust will not make any distribution of these funds to Unit holders until it receives a subsequent order from the Court or the
Remaining Matters are otherwise settled. In addition, the Trust may refrain from making any distribution of such proceeds until after the expiration of the audit period provided for in the conveyance
document for the 2016 Royalty Sale,
which expires on December 24, 2016. The lack of Net Proceeds and the inability to maintain adequate cash reserves raise substantial doubt about the Trust's ability to continue as a going
concern. The condensed financial statements do not include any adjustments that might result from the outcome of this uncertainty. See Note 2 to the condensed financial statements.

Special Cost Escrow Account

The special cost escrow account is an account of the Working Interest Owners and it is described herein for informational purposes only. The
Conveyance provides for the reserve of funds for estimated future "Special Costs" of plugging and abandoning wells, dismantling platforms and other costs of

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abandoning
the Royalty Properties, as well as for the estimated amount of future drilling projects and other capital expenditures on the Royalty Properties. Deposits into this account reduces current
distributions and are placed in an escrow account and invested in short-term certificates of deposit. Such account is herein referred to as the "Special Cost Escrow" account. All of the Partnership's
rights and obligations with respect to the Special Cost Escrow were assigned in connection with the Royalty Sales.

Three Months Ended September 30, 2016 and 2015



Royalty income was $0 for each of the three months ended September 30, 2016 and 2015, respectively. As a result of the Royalty Sale,
there were no gross proceeds for the underlying Royalty Properties attributable to the Trust for the production period of May, June and July 2016 attributable to the three months ended
September 30, 2016. Gross proceeds for the underlying Royalty Properties exceeded development and production costs by $326,576, or $195,946 attributable to the Trust for the production period
of May, June and July 2015 attributable to the three months ended September 30, 2015. The Net Proceeds were applied to reduce the accumulated excess cost carry forward, which represents the
amount by which the aggregate development and production costs for the Royalty Properties since November 2008 have exceeded the related proceeds of the protection, and as a result there was no royalty
income for the quarter ended September 30, 2015.

General
and administrative expenses for the Trust were $153,757 for the three months ended September 30, 2016 compared to $96,765 for the three months ended September 30,
2015. The increase is due, in part, to the costs associated with the Probate Proceeding.

The
reserve for future Trust expenses did not change from December 31, 2015 to September 30, 2016.

There
was no distributable income for each of the three months ended September 30, 2016 and September 30, 2015 and therefore no distributions to Unit holders.

For
the three months ended September 30, 2016 and September 30, 2015, the Trust had undistributed net income of $0 and $195,946, respectively, representing the Trust's
portion of the undistributed net income of $0 and $1,306,304 associated with the Royalty Properties for the three months ended September 30, 2016 and 2015. The undistributed net income was
applied to reduce the accumulated excess cost carry forward.



The following financial and operational information has been based on information provided to the Corporate Trustee by the Managing General
Partner. The Trustees had no control over these operations or internal controls relating to this information. The lack of revenues and production for the third quarter of 2016 are entirely
attributable to the February 1, 2016 effective time for the 2016 Royalty Sale and, as a result, no additional disclosure on the 100% decrease in revenues and production in the third quarter of
2016 compared to the third quarter of 2015 is provided.

Volumes
and dollar amounts discussed below represented amounts recorded by the Working Interest Owners unless otherwise specified.

20

---





Natural Gas and Gas Products

Gas revenues decreased 100% to $0 in the third quarter of 2016 from $115,077 in the third quarter of 2015. Gas volumes during the third quarter
of 2016 decreased 100% to 0 Mcf from 41,263 Mcf in the third quarter of 2015. The average price received for natural gas decreased 100% from an average price of $2.79 per Mcf in the third quarter of
2015 to $0 per Mcf in the third quarter of 2016, excluding the impact of the adjustments. Gas products revenue decreased 100% to $0 in the third quarter of 2016 from $17,858 in the third quarter of
2015. Gas products volumes during the third quarter of 2016 decreased 100% to 0 gallons compared to 47,820 gallons in the third quarter of 2015.

Crude Oil and Condensate

Crude oil and condensate revenues decreased 100% to $0 in the third quarter of 2016 from $2,109,957 in the third quarter of 2015. Oil volumes
decreased 100% from 34,749 barrels in the third quarter of 2015 to 0 barrels in the third quarter of 2016. The average price received for crude oil and condensate production decreased 100% to $0 per
barrel in the third quarter of 2016 from $60.72 per barrel in the third quarter of 2015, excluding the impact of the adjustments to Eugene Island 339 and Eugene Island 342.

Capital Expenditures

Capital expenditures decreased 100% to $0 in the third quarter of 2016 from $229 in the third quarter of 2015.

Production Expenses

Production expenses decreased 100% from $936,358 in the third quarter of 2015 to $0 in the third quarter of 2016.

Special Cost Escrow Account

In the third quarter of 2016, there were no funds released from or escrowed into the Special Cost Escrow account. As of September 30,
2016, $1,000 remained in the Special Cost Escrow account. The funds held in the Special Cost Escrow account were not reflected in the condensed financial statements of the Trust. All of the
Partnership's rights and obligations with respect to the Special Cost Escrow were assigned in connection with the Royalty Sales.

Summary By Property

Listed below is a summary of operations of the principal Royalty Properties for the third quarter of 2016 as compared to operations for the
third quarter of 2015 based on gross
revenues generated during these periods combined. All decreases in revenues and production for the third quarter of 2016 are entirely attributable to the February 1, 2016 effective time for the
2016 Royalty Sale.

Eugene Island 339

Net crude oil revenues decreased from $501,115 in the third quarter of 2015 to $0 in the third quarter of 2016. Net crude oil production
decreased from 8,518 barrels in the third quarter of 2015 to 0 barrels in the third quarter of 2016. Gas revenues decreased from $18,399 in the third quarter of

21

---



2015
to $0 in the third quarter of 2016. Gas production decreased from 5,919 Mcf in the third quarter of 2015 to 0 Mcf in the third quarter of 2016. Capital expenditures were $0 in the third quarter
of 2015 and the third quarter of 2016. Operating expenses decreased from $44,781 in the third quarter of 2015 to $0 in the third quarter of 2016.

Ship Shoal 182/183

Net crude oil revenues decreased from $1,562,975 in the third quarter of 2015 to $0 in the third quarter of 2016. Net crude oil production
decreased from 25,440 barrels in the third quarter of 2015 to 0 barrels in the third quarter of 2016. Gas revenues decreased from $93,909 in the third quarter of 2015 to $0 in the third quarter of
2016. Capital expenditures decreased from $231 in the third quarter of 2015 to $0 in the third quarter of 2016. Operating expenses decreased from $787,045 in the third quarter of 2015 to $0 in the
third quarter of 2016.

South Timbalier 36/37

Net crude oil revenues decreased from $40,391 in the third quarter of 2015 to $0 for the same period in 2016. Gas revenues decreased from $2,727
in the third quarter of 2015 to $0 in the third quarter of 2016. Gas production decreased from 1,095 Mcf in the third quarter of 2015 to 0 Mcf in the third quarter of 2016. Capital expenditures were
$0 in the third quarter of 2015 and 2016. Operating expenses decreased from $11,926 in the third quarter of 2015 to $0 in the third quarter of 2016.

Eugene Island 342

Net crude oil revenues decreased from $5,476 in the third quarter of 2015 compared to $0 in the third quarter of 2016. Net crude oil production
decreased from 107 barrels in the third quarter of 2015 to 0 barrels in the third quarter of 2016. Gas revenues were $41 and gas production was 15 Mcf in the third quarter of 2015, compared to gas
revenues of $0 and gas production of 0 Mcf in the third quarter of 2016. As the underlying interest in Eugene Island 342 is an overriding royalty interest, there were no capital or operating expenses
recorded in the third quarter of 2016 and 2015.

Nine Months Ended September 30, 2016 and 2015



Royalty income was $117,142 and $0 for the nine months ended September 30, 2016 and 2015, respectively. Gross proceeds for the underlying
Royalty Properties exceeded development and production costs by $1,156,741, or $173,511 attributable to the Trust, for the production period of November and December 2015 and January, February, March,
April, May, June and July 2016 attributable to the nine months ended September 30, 2016 and by $4,261,214, or $639,183 attributable to the Trust for the production period of November and
December 2014 and January, February, March, April, May, June and July 2015 attributable to the nine months ended September 30, 2015. The Net Proceeds were applied to reduce the accumulated
excess cost carry forward, which represents the amount by which the aggregate development and production costs for the Royalty Properties since November 2008 have exceeded the related proceeds of the
protection, and as a result there was no royalty income for the nine months ended September 30, 2016 and 2015.

22

---



General
and administrative expenses for the Trust were $477,851 for the nine months ended September 30, 2016 compared to $334,255 for the nine months ended September 30,
2015. The increase is due, in part, to the costs associated with the Probate Proceeding.

The
reserve for future Trust expenses did not change from December 31, 2015 to September 30, 2016 and remained at $0.

There
was no distributable income for each of the nine months ended September 30, 2016 and September 30, 2015 and therefore no distributions to Unit holders.

For
the nine months ended September 30, 2016 and September 30, 2015, the Trust had undistributed net income of $173,511 and $639,183, respectively, representing the Trust's
portion of the undistributed net income of $1,094,037 and $4,261,214 associated with the Royalty Properties for the nine months ended September 30, 2016 and 2015. The undistributed net income
was applied to reduce the accumulated excess cost carry forward.



The following financial and operational information has been based on information provided to the Corporate Trustee by the Managing General
Partner. The Trustees had no control over these operations or internal controls relating to this information. Decreases in revenues and production for the nine months ended September 30, 2016
are all primarily attributable to the February 1, 2016 effective time for the 2016 Royalty Sale.

Volumes
and dollar amounts discussed below represent amounts recorded by the Working Interest Owners unless otherwise specified.

Natural Gas and Gas Products

Gas revenues decreased $458,394, or 85.0%, to $81,116 in the first nine months of 2016 from $539,510 in the first nine months of 2015. Gas
volumes during the first nine months of 2016 decreased 72.3% to 43,878 Mcf from 158,499 Mcf in the first nine months of 2015. Excluding the impact of prior period adjustments, the average price
received for natural gas decreased approximately 54.1% from an average price, excluding adjustments, of $3.40 per Mcf in the first nine months of 2015 to $1.56 per Mcf in the first nine months of
2016. Also as a result of the adjustments, gas products volumes during the first nine months of 2016 decreased 59.6% to 62,956 gallons, compared to 155,775 gallons in the first nine months of 2015.

Crude Oil and Condensate

Crude oil and condensate revenues decreased $4,724,915, or 72.7%, to $1,777,748 in the first nine months of 2016 from $6,502,663 in the first
nine months of 2015. Excluding the impact
of prior period adjustments, the average price received for crude oil and condensate production decreased 36.7%, or $22.79, to $39.23 per barrel in the first nine months of 2016 from $62.02 per barrel
in the first nine months of 2015. Oil volumes decreased 56.8% from 104,851 barrels in the first nine months of 2015 to 45,320 barrels in the first nine months of 2016.

23

---



Capital Expenditures

Capital expenditures decreased 100% from $933 in the first nine months of 2015 to $0 in the first nine months of 2016.

Production Expenses

Production expenses decreased by $2,052,137, or 72.2%, from $2,841,709 in the first nine months of 2015 to $779,572 in the first nine months of
2016.

Special Cost Escrow Account

In the first nine months of 2016, there were no funds released from or escrowed into the Special Cost Escrow account. As of September 30,
2016, $0 remained in the Special Cost Escrow account. The funds held in the Special Cost Escrow account were not reflected in the condensed financial statements of the Trust. The Special Cost Escrow
account was set aside for
estimated abandonment costs and future capital expenditures, as provided for in the Conveyance. For additional information relating to the Special Cost Escrow account, see "Special Cost
Escrow Account" below.

Summary By Property

Listed below is a summary of operations of the principal Royalty Properties for the first nine months of 2016 as compared to operations for the
first nine months of 2015 based on gross revenues generated during these periods combined. Decreases in revenues and production for the nine months ended September 30, 2016 are all primarily
attributable to the February 1, 2016 effective time for the 2016 Royalty Sale.

Eugene Island 339

Eugene Island 339 net crude oil revenues decreased from $1,722,499 in the first nine months of 2015 to $662,064 in the first nine months of
2016. There was also a decrease in net crude oil production from 27,778 barrels in the first nine months of 2015 to 17,976 barrels in the first nine months of 2016. Gas revenues decreased from $63,853
in the first nine months of 2015 to $58,949 in the first nine months of 2016. Gas production increased from 17,471 Mcf in the first nine months of 2015 to 27,145 Mcf in the first nine months of 2016.
Capital expenditures were $0 the first nine months of 2016 and 2015. Operating expenses decreased from $103,567 in the first nine months of 2015 to $23,078 in the first nine months of 2016 due in part
to decreased maintenance costs in the first nine months of 2016 as compared to the first nine months of 2015.

Ship Shoal 182/183

Ship Shoal 182/183 net crude oil revenues decreased from $4,901,958 in the first nine months of 2015 to $1,090,667 in the first nine months of
2016, due in part to a decrease in the
average crude oil price received from $63.62 per barrel in the first nine months of 2015 to $40.84 per barrel for the same period in 2016. There was also a decrease in net crude oil production from
77,053 barrels in the first nine months of 2015 to 26,706 barrels in the first nine months of 2016. Gas revenues decreased from $438,666 in the first nine months of 2015 to $20,547 in the first nine
months of 2016. There was also a decrease in the average gas revenue price received from $3.31 per Mcf in the first nine months of 2015 to $1.29 per Mcf for the same period in 2016. Capital
expenditures decreased from $1,091 in the first

24

---



nine
months of 2015 to $0 in the first nine months of 2016. Operating expenses decreased from $2,407,955 in the first nine months of 2015 to $676,682 for the same period in 2016.

South Timbalier 36/37

South Timbalier 36/37 crude oil revenues decreased from $179,409 in the first nine months of 2015 to $20,407 for the same period in 2016 due
primarily to a decrease in the average crude oil price received from $65.14 per barrel in the first nine months of 2015 to $39.58 per barrel in the first nine months of 2016. There was also a decrease
in oil production volumes from 2,754 barrels in the first nine months of 2015 to 516 barrels in the first nine months of 2016. Gas revenues decreased from $9,802 in the first nine months of 2015 to
$1,553 in the first nine months of 2016 due to a decrease in the average natural gas price received from $3.11 per Mcf in the first nine months of 2015 to $1.98 per Mcf in the first nine months of
2016. There was also a decrease in gas production from 3,152 Mcf in the first nine months of 2015 to 783 Mcf in the first nine months of 2016. Capital expenditures decreased from a benefit of $157 in
the first nine months of 2015 to $0 in the first nine months of 2016. Operating expenses decreased from $40,482 in the first nine months of 2015 to $10,577 in the first nine months of 2016.

Eugene Island 342

Net crude oil revenues increased from negative $301,203 in the first nine months of 2015 to $4,610 in the first nine months of 2016. This
increase is primarily due to a prior period adjustment in net crude oil production from negative 2,733 barrels in the first nine months of 2015 to 123 barrels in the first nine months of 2016. Gas
revenues were $66 and gas production was 56 Mcf in the first nine months of 2016, compared to gas revenues of $27,188 and gas production of 5,373 Mcf in the first nine months of 2015. As the
underlying interest in Eugene Island 342 is an overriding royalty interest, there were no capital or operating expenses recorded in the first nine months of 2016 and 2015.

Overview of Production, Prices and Royalty Income

The following schedule provides a summary of the volumes and weighted average prices for crude oil and condensate and natural gas recorded by
the Working Interest Owners for the Royalty Properties, as well as the Working Interest Owners' calculations of the Net Proceeds and Royalties paid to the Trust during the periods indicated. The
following information for the three and nine months

25

---



ended
September 30, 2015 includes the effect of the audit adjustments of Eugene Island 339 and Eugene Island 342.



Royalty Properties Three
Months Ended
September 30,(1)

Royalty Properties Nine
Months Ended
September 30,(1)2016

2015

2016

2015Crude oil and condensate (bbls)





34,749


45,320


104,851Natural gas and gas products (Mcfe)





49,233


43,878


184,461Crude oil and condensate average price, per bbl(2)

$


$
60.72

$
39.23

$
62.02Natural gas average price, per Mcf (excluding gas products)(3)

$


$
2.79

$
1.85

$
3.40Crude oil and condensate revenues

$


$
2,109,957

$
1,777,748

$
6,502,663Natural gas and gas products revenues





132,935


81,116


601,193Production expenses





(936,358
)

(779,572
)

(2,841,709
)Capital expenditures





(229
)




(933
)InterestUndistributed net income(4)





(1,306,304
)

(1,094,037
)

(4,261,214
)Refund of (provision for) Special Cost Escrow











​
​
​
​
​
​
​
​
​
​
​
​
​
​Net Proceeds











Royalty interest



(5)

X15
%


(5)

X15
%​
​
​
​
​
​
​
​
​
​
​
​
​
​Partnership share











Trust interest


x99.99
%

x99.99
%

x99.99
%

x99.99
%​
​
​
​
​
​
​
​
​
​
​
​
​
​Trust share of Royalty Income(6)

$


$


$


$
​
​
​
​
​
​
​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​
​
​
​
​
​
​


(1)Amounts
were based on production for the three- and nine-month period ended July 31 of each year, respectively, and included the results of the adjustments
for Eugene Island 339 and Eugene Island 342.(2)Excluding
the adjustments, the average price for the three months ended September 30, 2016 and 2015 was $0 and $60.75, respectively, and for the nine months
ended September 30, 2016 and 2015 was $39.14 and $62.10, respectively, per barrel.(3)Excluding
the adjustments, the average price for the three months ended September 30, 2016 and 2015 was $0 and $2.79, respectively, and for the nine months
ended September 30, 2016 and 2015 was $1.56 and $3.35, respectively, per Mcf.(4)Undistributed
net loss represented the amount of development and production costs associated with the Royalty that exceeded the proceeds of production from the
Royalty Properties during the period. An undistributed net loss was carried forward and offset, in future periods, by positive proceeds earned by the related Working Interest Owner(s). Undistributed
net income represented positive Net Proceeds, generated during the respective period, but not distributed by the Working Interest Owners. For the three months ended September 30, 2016, the
Trust had no undistributed net income.(5)As
a result of the 2016 Royalty Sale, the Royalty interest was reduced from 15% to zero.


26

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(6)See
"Trustee's Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources" and Note 4 to the Notes
to the Condensed Financial Statements under Item 1 of Part I of this Form 10-Q for a discussion regarding uncertainty of distributions.


Critical Accounting Policies

Disclosure of critical accounting policies and the more significant judgments and estimates used in the preparation of the Trust's financial
statements are included in Item 7 of the 2015 10-K. There have been no significant changes to the critical accounting policies during the three months ended September 30, 2016.

New Accounting Pronouncements

There were no accounting pronouncements issued during the three months ended September 30, 2016 applicable to the Trust or its condensed
financial statements.

Off-Balance Sheet Arrangements

The Trust had no off-balance sheet arrangements. The Trust had not guaranteed the debt of any other party, nor did the Trust have any other
arrangements or relationships with other entities that could have potentially resulted in unconsolidated debt, losses or contingent obligations.

Item 3.    Quantitative and Qualitative Disclosures About Market Risk.

Prior to effective time of the 2016 Royalty Sale, the only assets of and sources of income to the Trust were cash and the Trust's interest in
the Partnership, which was the holder of the Royalty. As a result, the Trust was exposed to market risk associated with the Royalty from fluctuations in oil and gas prices. See Note 2 of the
Notes to Condensed Financial Statements.

The
Trust has in the past borrowed, and is expected to continue to borrow, money to pay expenses of the Trust. As a result, the Trust is exposed to interest rate market risk associated
with the money borrowed to pay expenses.

Item 4.    Controls and Procedures.

Evaluation of disclosure controls and procedures.The Corporate Trustee maintains disclosure controls and procedures designed to ensure
that
information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within
the time periods specified in the SEC's rules and regulations. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the
Trust is accumulated and communicated by Chevron, as the Managing General Partner of the Partnership, and the Working Interest Owners to the Corporate Trustee of the Trust, and its employees who
participate in the preparation of the Trust's periodic reports as appropriate to allow timely decisions regarding required disclosure.

As
disclosed in the Trust's Quarterly Report on Form 10-Q for the quarter ended March 31, 2016. Chevron notified the Corporate Trustee of errors in the working interest and
net revenue interest used in calculating the net reserves attributable to the Royalty Properties and in preparing the net profits statements for the Royalty Properties and the Trust. The errors in the
working interests and net revenue interests have been corrected and the Corporate Trustee does not anticipate any future similar

27

---



issues
affecting the Trust's ability to timely file or submit reports required under the Securities Exchange Act of 1934, as amended. As of the end of the period covered by this report, the Corporate
Trustee carried out an evaluation of the Trust's disclosure controls and procedures. Michael J. Ulrich, as Trust Officer of the Corporate Trustee, has concluded that the disclosure controls and
procedures of the Trust were effective as of September 30, 2016.

Due
to the previous contractual arrangements of (i) the Trust Agreement, (ii) the Partnership Agreement and (iii) the rights of the Partnership under the Conveyance
regarding information furnished by the Working Interest Owners, the Trustees relied on (A) information provided by the Working Interest Owners, including historical operating data, plans for
future operating and capital expenditures, reserve information and information relating to projected production, (B) information from the Managing General Partner of the Partnership, including
information that is collected from the Working Interest Owners, and (C) conclusions and reports regarding reserves by the Trust's independent reserve engineers. See Item 1A. Risk Factors
"The Trustees and the Unit holders had no control over the operation or development of the Royalty Properties and had little influence over operation or development" and "The Trustees
rely upon the Working Interest Owners and Managing General Partner for information regarding the Royalty Properties" in the 2015 Form 10-K for a description of certain risks relating to these
arrangements and reliance on and applicable adjustments to operating information when reported by the Working Interest Owners to the Corporate Trustee and recorded in the Trust's results of operation.

Changes in Internal Control Over Financial Reporting.During the three months ended September 30, 2016, there has been no change in
the
Trust's internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Trust's internal control over financial reporting. The Corporate
Trustee notes for purposes of clarification that it had no authority over, and makes no statement concerning, the internal control over financial reporting of the Working Interest Owners or the
Managing General Partner of the Partnership.

28

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PART IIOTHER INFORMATION

Item 1.    Legal Proceedings.

On July 10, 2014, the Trustees filed a Petition for Modification and Termination of the Trust (the "Petition") with the Probate Court of
Travis County, Texas (the "Court"). The Petition requested that the Court modify the Trust Agreement to (1) allow for the termination of the Trust by a court order, and (2) allow the
Trustees, as necessary to fulfill the purposes of the Trust and without Unit holder approval to (a) sell all or any portion of the Trust's interests in the Partnership or any other assets of
the Trust, (b) exercise their rights to dissolve the Partnership, or (c) cause the Partnership to sell the Royalty. The goals in filing such probate proceeding (the "Probate Proceeding")
were to permit the Trustees to direct the Partnership to sell the Royalty; to distribute the net proceeds resulting from such sale, after payment of the Trust's liabilities, to the Unit holders; and,
to, thereafter terminate the Partnership and the Trust. The Trust has completed the process of serving the Petition on the Trust's Unit holders. The Court appointed an attorney ad litem to represent
any Unit holders that were not personally served. The Court appointed attorney ad litem filed a Counterclaim against the Trust on November 16, 2015 requesting (1) an order to sell all of
the Royalty, and (2) an accounting of the general and administrative expenses of the Trust from 2008 through the present.

The
Probate Proceeding was set for trial on January 15, 2016. Prior to trial, the attorney ad litem filed a Motion to Sever asking the Court to sever all matters related to the
requested modification of the Trust and the sale of Trust assets, as plead for, in part, in the petition originally filed by the Trustees and in the attorney ad litem's Counterclaim, into a separate
cause to proceed to trial. The attorney ad litem also filed a Motion for Continuance requesting that the Court continue the trial of all remaining matters, including the attorney ad litem's request
for an accounting and the issues concerning the termination of the Trust, to a later date (the "Remaining Matters"). Prior to calling the case to trial, the Court granted the attorney ad litem's
Motion to Sever and Motion for Continuance, severed the matters related to the modification of the Trust and the sale of Trust assets ("Severed Proceeding"), and continued the Remaining Matters to a
later date. The Severed Proceeding has been assigned Cause No. C-1-PB-16-000096 and is styledIn re: TEL Offshore Trust.

The
Severed Proceeding proceeded to trial before the Court on January 15, 2016. At trial, the Court entered a final judgment granting the Trustees' request that the Trust
Agreement be modified to permit the Trustees to direct the Partnership to sell the remaining overriding royalty interest held by the Partnership as soon as reasonably possible and granting the ad
litem's request to sell all of the Royalty, notwithstanding any requirements of the Trust Agreement to the contrary. Thereafter, the Court ordered that the Trustees direct the Partnership to sell all
of the Royalty owned by the Partnership on or before May 1, 2016. On April 25, 2016, the Court approved an extension of the May 1, 2016 deadline to June 30, 2016.

On
August 17, 2016, the attorney ad litem filed a Second Amended Answer and First Amended Counterclaim seeking an accounting and asserting, among other causes of action, that the
Trustees have breached their fiduciary duties to the beneficiaries of the Trust. The Remaining Matters were originally set for trial on November 7, 2016. Trustees filed a motion for continuance
of the Remaining Matters and a hearing for such continuance occurred on September 14, 2016. At the hearing, the Court granted the Trustees' motion for continuance of the Remaining Matters and
scheduled the trial for June 12, 2017. There can be no assurances as to the outcome of the Remaining Matters and whether the Court will grant the requested relief, and if such relief is
granted, when such actions will be completed.

29

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Item 1A.    Risk Factors.

There have not been any material changes from the risk factors previously disclosed in the Trust's response to Item 1A. to Part 1
of the 2015 10-K.

Item 6.    Exhibits.

(Asterisk indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference.)



SEC File or
Registration
Number

Exhibit
Number4(a)
*


Trust Agreement dated as of January 1, 1983, among Tenneco Offshore Company, Inc., Texas Commerce Bank National Association, as corporate trustee, and Horace C. Bailey, Joseph C. Broadus and F. Arnold Daum, as
individual trustees (Exhibit 4(a) to Form 10-K for the year ended December 31, 1992 of TEL Offshore Trust)

0-06910

4(a)4(b)
*


Agreement of General Partnership of TEL Offshore Trust Partnership between Tenneco Oil Company and the TEL Offshore Trust, dated January 1, 1983 (Exhibit 4(b) to Form 10-K for year ended December 31,
1992 of TEL Offshore Trust)

0-06910

4(b)4(c)
*


Conveyance of Overriding Royalty Interests from Exploration I to the Partnership (Exhibit 4(c) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)

0-06910

4(c)4(d)
*


Amendments to TEL Offshore Trust Agreement, dated December 7, 1984 (Exhibit 4(d) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)

0-06910

4(d)4(e)
*


Amendment to the Agreement of General Partnership of TEL Offshore Trust Partnership, effective as of January 1, 1983 (Exhibit 4(e) to Form 10-K for the year ended December 31, 1992 of TEL Offshore
Trust)

0-06910

4(e)10(a)
*


Purchase Agreement, dated as of December 7, 1984 by and between Tenneco Oil Company and Tenneco Offshore II Company (Exhibit 10(a) to Form 10-K for year ended December 31, 1992 of TEL Offshore
Trust)

0-06910

10(a)10(b)
*


Consent Agreement, dated November 16, 1988, between TEL Offshore Trust and Tenneco Oil Company (Exhibit 10(b) to Form 10-K for year ended December 31, 1988 of TEL Offshore Trust)

0-06910

10(b)


30

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SEC File or
Registration
Number

Exhibit
Number10(c)
*


Assignment and Assumption Agreement, dated November 17, 1988, between Tenneco Oil Company and TOC-Gulf of Mexico Inc. (Exhibit 10(c) to Form 10-K for year ended December 31, 1988 of TEL Offshore
Trust)

0-06910

10(c)10(d)
*


Gas Purchase and Sales Agreement Effective September 1, 1993 between Tennessee Gas Pipeline Company and Chevron U.S.A. Production Company (Exhibit 10(d) to Form 10-K for year ended December 31, 1993 of
TEL Offshore Trust)

0-06910

10(d)31



Certification furnished pursuant to Section 302 of the Sarbanes-Oxley Act of 200232



Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002


31

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.



TELOFFSHORE TRUSTBy:

The Bank of New York Mellon
Trust Company, N.A.
Corporate TrusteeBy:

/s/ MICHAEL J. ULRICH Michael J. Ulrich Vice President


Date:
November 14, 2016

The
Registrant, TEL Offshore Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no
additional signatures are available and none have been provided.

32

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